The present invention relates to a method for separating a feed stream, comprising hydrogen sulphide (H2S), carbon dioxide (CO2), and one or both of hydrogen (H2) and carbon monoxide (CO), into at least a CO2 product stream and an H2 or H2 and CO product stream. The invention has particular application in the separation of a sour (i.e. sulphur containing) syngas, as for example may be obtained from the gasification of solid or liquid carbonaceous feedstock, to obtain: a CO2 rich product stream suitable for geological storage; an H2 or H2 and CO product stream suitable for use in a chemicals plant or refinery, or as fuel for a gas turbine; and, optionally but preferably, an H2S enriched stream that can be further processed, e.g. in a Claus unit or other suitable sulphur recovery system, in order to convert to elemental sulphur the H2S contained therein.
It is well known that streams comprising H2 and CO can be produced via gasification of solid or liquid feedstock. However, such processes result in a crude syngas stream containing, in addition to H2 and CO, also CO2 and H2S. The CO2 arises from the partial combustion of the feedstock during gasification, the concentration of which is increased if the crude syngas steam is subjected to a water-gas shift reaction to convert by reaction with H2O all or part of the CO in the stream to CO2 and H2. The H2S arises from the reduction of sulphur present in the feedstock during gasification, and from further conversion of other sulphur species in the crude syngas stream to H2S during the water-gas shift reaction.
Due to concerns over greenhouse gas emissions, there is a growing desire to remove CO2 from syngas prior to its use (e.g. as a combustion fuel). The CO2 may be compressed so as to be stored underground. H2S must also be removed from the syngas as it could be a poison for downstream processes, or if the syngas is combusted in a gas turbine then the H2S is converted into SO2, which has limits on its emission and so would need to be removed using expensive desulphurization technology on the combustion exhaust gas.
After separating the H2S and CO2 from the syngas, it may not be practical or permissible to store the H2S with the CO2. Therefore a solution must also be found for cost effective removal of the H2S from the CO2 before pipeline transportation.
The currently used commercial solution for this problem is to use a liquid absorption process (e.g. Selexol™, Rectisol® or other such acid gas removal process) that removes the CO2 and H2S from the syngas. The CO2 is obtained as a product gas of sufficient purity that it can be directly pressurized and piped to storage or enhanced oil recovery (EOR). The H2S is obtained as an H2S enriched mixture comprising 20-80 mole % H2S, which mixture can then be sent to, for example, a Claus unit to produce elemental sulphur. However, such liquid adsorption processes are costly (both in terms of capital and operating cost) and have significant power consumption.
US-A1-2007/0178035 describes a method of treating a gaseous mixture comprising H2, CO2 and at least one combustible gas selected from the group consisting of H2S, CO and CH4. H2 is separated from the gaseous mixture, preferably by a pressure swing adsorption (PSA) process, to produce a separated H2 gas and a crude CO2 gas comprising the combustible gas(es). The crude CO2 gas is then combusted in the presence of O2 to produce heat and a CO2 product gas comprising combustion products of the combustible gas(es). The combustible gas may be H2S, in which case the combustion products are SO2 and SO3 (SOX) and H2O. The CO2 product gas can then be washed with water to cool the gas and convert SO3 to sulfuric acid, and maintained at elevated pressure in the presence of O2, water and NOx to convert SO2 and NOx to sulfuric acid and nitric acid.
Thus, in the process described in US-A1-2007/0178035, H2S is removed by conversion to SOx and then H2SO4, and is not available for subsequent conversion to elemental sulphur in a Claus unit. Any H2/CO present in the crude CO2 gas is also combusted, and thus lost as potential product.
US-A1-2008/0173585 describes a method of purifying an impure CO2 stream by partial condensation. The method comprises compressing impure CO2 gas, condensing at least a portion of the compressed gas to produce impure CO2 liquid; expanding at least a portion of said impure CO2 liquid to produce expanded impure CO2 liquid; and separating at least a portion of said expanded impure CO2 liquid in a mass transfer separation column system to produce a contaminant-enriched overhead vapor and CO2 bottoms liquid. In one embodiment, the impure CO2 is obtained from waste gas from a hydrogen PSA process, the contaminants removed being H2, CO, nitrogen, methane and argon. In the embodiment depicted in FIGS. 2 and 3 of the document, a temperature swing adsorption (TSA) unit is used to remove water from the impure CO2 stream prior to the partial condensation process, so as to prevent water from freezing and blocking the heat exchanger.
US-A1-2008/0173584 describes a similar method to that described in US-A1-2008/0173585.
US-A1-2007/0232706 describes a method of producing a carbon dioxide product stream from a hydrogen plant. In one embodiment, a vacuum pressure swing adsorption (VPSA) unit is used to separate a crude CO2 stream from at least part of a syngas stream from a steam-methane reformer. The crude CO2 is compressed, passed through a temperature pressure swing adsorption (TPSA) unit to dry the stream, and partially condensed and distilled to obtain liquid CO2 product stream, a CO2 rich vapour, and a CO2 depleted vapour, the latter being recycled to the VPSA unit.
Chemical Engineering Journal 155 (2009) 594-602, “Desulfurization of air at high and low H2S concentrations”, describes the capability to separate H2S from air using adsorption on activated carbon. It also describes a potential advantage of the presence of water vapour in the feed stream in enhancing H2S uptake for at least one type of modified activated carbon.
Adsorption 15 (2009) 477-488, “Enhanced removal of hydrogen sulfide from a gas stream by 3-aminopropyltriethoxysilane-surface-functionalized activated carbon”, describes the capability to separate H2S from Claus tail gas using adsorption on activated carbon. This document also suggests that for some carbon adsorbents, the presence of water in the feed stream may enhance the H2S capacity.
US-B2-7306651 describes the separation of a gas mixture comprising H2S and H2 using the combination of a PSA unit with a membrane. The PSA separates the feed stream into a H2 stream and two H2S-rich streams. One H2S-rich stream is recovered as product and the second is compressed and put through a membrane to remove the H2. The H2S is then supplied to the PSA unit at pressure for rinsing and the H2 returned to the PSA unit for purging.
EP-B1-0444987 describes the separation of CO2 and H2S from a syngas stream produced by gasification of coal. The syngas stream, containing H2S, is reacted with steam in a catalytic CO-shift reactor to convert essentially all the CO in the stream to CO2. The stream is sent to a PSA unit that adsorbs CO2 and H2S in preference to H2, to separate the stream into an H2 product gas and a stream containing CO2 and H2S. The stream containing CO2 and H2S is sent to a second PSA unit that adsorbs H2S in preference to CO2, to provide a CO2 product, stated to be of high purity, and a H2S containing stream, which is sent to a Claus unit for conversion of the H2S into elemental sulphur.
There is a continuing need for new methods of separating sour syngas streams, and other streams comprising H2S, CO2, H2 and optionally CO. In particular, there is a need for methods that can, preferably at lower cost and/or with lower power consumption than the current commercially used methods, separate such streams to obtain: an H2 or H2 and CO product of sufficient purity for refinery, chemicals or power applications; a CO2 product of suitable purity for geological storage or EOR; and, preferably, a H2S containing product of suitable composition for further processing in a sulphur recovery system to convert the H2S to elemental sulphur.